Mexico opened the door for the world’s oil and gas companies to pursue deepwater exploration in the southern Gulf of Mexico (GoM), but replicating the success seen on the U.S. side could be challenging for those that have entered.

Geology could pose obstacles, according to analysts.

“The southern GoM is not a direct analogue to its conjugate in the North,” Vikesh Mistry, a global exploration research analyst for Westwood Energy, said in a report. “Tectonic processes related to Pacific plate motions contribute to making this part of the GoM structurally more complex.”

Oil and gas companies—majors and smaller companies alike—have flocked to deepwater bidding rounds offered by the Mexican government in hopes of finding hydrocarbons beneath the seafloor in what Westwood calls a “largely frontier” area. Two deepwater rounds offered in 2017 and 2018 resulted in just under 30 blocks—with the Campeche Salt Basin’s Miocene turbidite play getting the most attention—being awarded to 17 companies. Together the companies have committed to drill a total of 31 wells, according to the consultancy.

But even operators in the U.S. northern GoM, where emerging plays including the Paleogene Wilcox have resulted in 3.2 billion barrels of oil equivalent (Bboe) in commercial production since 2008, have faced technical obstacles. High pressures and temperatures, for example, have kept the commercial success rate to only 16%, Mistry said in the report.

Mistry shared more insight with Hart Energy on frontier and emerging deepwater plays of the GoM.

Hart Energy: What makes the southern GoM more structurally complex than the northern GoM, and how are some operators planning to tackle these reservoirs?

Mistry: There are two key factors which differentiate the northern GoM and the southern GoM. Firstly, in the northern GoM vast river systems onshore U.S. drain two-thirds of the country and have been responsible for bringing large volumes of sand into the deep water. In contrast, the river systems feeding the southern GoM are smaller and less extensive and bring smaller amounts of more variable sediments into the basin.

The second key difference is the role of Pacific plate tectonics. A major Mid Miocene event (called the Chiapaneco Orogeny) caused intense folding and thrusting in the southern GoM but had no effect in the northern GoM. This led to the creation of traps for the giant Mesozoic fields of the shallow waters but is also responsible for the squeezing and distortion of the salt in the deep water. The combination of these two factors will bring different challenges to exploration in the southern GoM compared to the north in terms of reservoir quality and distribution, charge and trap integrity.

With 31 wells committed across the southern GoM in the last two deepwater license rounds, over the next few years, the industry will need to apply the hard-learnt knowledge of exploring the Northern GoM into the Southern GoM.

Hart Energy: How high are the pressures and temperatures in the Northern GoM Paleogene Wilcox and Upper Jurassic Norphlet plays? What technologies have been developed or are in the works to combat these challenges?

Mistry: Both the Upper Jurassic Norphlet and Paleogene Wilcox plays have HP/HT conditions. Many of the Wilcox discoveries, such as Anchor and Shenandoah, are beyond the current technical limit of 15,000 psi pressure and 275 F temperature. The industry is working at developing equipment capable of operating at 20,000 psi and 350-400 F to unlock these resources. Shell’s Upper Jurassic Appomattox development will use facilities rated to operate at more than 400F (Subsea Engineering News, Dec. 4, 2015).

Primary recovery factors in the Paleogene play are likely to be less than 10% due to the presence of clay rich, low permeability reservoirs. Companies will likely need to invest in secondary recovery schemes such as deepwater subsea water and gas injection as well as artificial lift in order to maximize recovery.

Hart Energy: What are your thoughts on the potential presalt play in the Mexican GoM? How does it compare to the presalt plays offshore Brazil?

Mistry: With over 30 Bboe discovered resource, the deepwater presalt carbonate play in Brazil is the largest oil province to have been opened this century. The presalt plays of the Mexican GoM are onshore and in shallow water and of a different geological age. No wells have yet tested the presalt plays of the deepwater Mexican GoM and little is known about the geology or its potential at this stage.

The Yaaxtaab-1 well in Mexico spud in November 2017. It is located in shallow water close to the giant Cantarell complex of fields and will test a frontier presalt play below existing production from post-salt reservoirs. A discovery at Yaaxtaab would be a play opener for the Mexican southern GoM.

Many in the industry are eagerly awaiting the results. The presalt potential of the basin was briefly discussed by panelists speaking on Mexico’s E&P activity and potential during Enercom’s The Oil & Gas Conference. Oscar Roldan of Mexico’s National Hydrocarbons Commission mentioned the excitement surrounding Mexico’s presalt basin.

“It hasn’t been tested yet and we expect that probably that will be one of the biggest surprises just [as in Brazil],” Roldan said, adding most of state-run Pemex’s production has come from above the salt. “We’re quite excited to see what the companies can find below the salt. They have fresh new data—3-D wide azimuth seismic—just freshly acquired. So probably the best is still yet to come, and we hope to see many more discoveries.”

Velda Addison can be reached at vaddison@hartenergy.com.